Smart grids- and their limits

Smart grids are integrated power systems designed to allow energy supply and demand to be balanced efficiently, in part by the use of electronic control and management systems. Some of this involves new hardware: energy stores that can be called on when supply is low and demand is high, or back-up plants queued up to meet demand peaks and green energy supply lulls. But some may be just software. For example, variable energy pricing signals sent to consumers may depress demand when supply is low or demand high. This is sometimes called ‘demand response’, and one variant relies on the ability of some domestic and retail  systems (eg freezers) to cope happily for a few hours without power, so that they can be set up to go offline when energy demand is high or supply low. 

The smart grid concept is seen as offering a new more flexible approach to energy supply and use, enabling the wider use of variable renewables and reducing the need for ‘always on’ base-load power. 

There are many practical problems facing the development and integration of such systems, as has already been found with the deployment of the relatively simple smart meters in the UK. The much more complex smart grid will no doubt require even more effort and adjustments, particularly in relation to consumer reactions. For example, consumers may not be happy with interactive load management systems that automatically isolate loads when demand is high- even if that saves them money. It may be better to offer them the choice of pre-setting cut off price levels, and also an over-ride option, so that they can, for example, continue to charge their electric car or run a washing machine even if the price of doing so at that time will be high. There are also issues with the integration of storage into smart grid systems: ideally they should store power when its cheap and use it when its expensive, but, in the case of Vehicle to Grid storage systems, will electric car owners be happy to find that power has been drained out of their batteries if they want to drive somewhere at around peak demand time.  Contractual limits have to be set and consumer friendly interactive control systems developed. Unsurprisingly then, at both the technical and social level, smart grid and demand response systems are currently a big area of research:  http://www.sciencedirect.com/science/article/pii/S1364032113007211

However, there is a larger problem. This sort of system can only deal with relatively small and short-term supply shortfalls.  As a review of smart grids posted on the Energy Matters web site concluded ‘no smart grid is smart enough to generate electricity when the wind doesn’t blow and the sun doesn’t shine’. That seems clear if there are long lulls, but its actually a bit of a simplification: it may not be the case if the concept of smart grids is expanded. 

It is true that demand management can only shift demand peaks by a few hours or in the extreme (with some industrial-scale interruptible contracts) a day or so. Similarly, storage system like batteries can only meet lulls for a few hours or at best a day or so, whereas there can be long lulls in wind and solar inputs, for several days or even a week or more, sometimes across wide areas.  However, studies have suggested that it will be rare for whole continents to be entirely becalmed and cloudy for long periods, so if they are spread widely enough, long distance HVDC supergrid interconnectors can often deal with lulls in some parts by trading power from where there is surplus to where it is needed. For example, the weather systems differ across Eastern and Western, and Northern and Southern Europe and North Africa. Of course there may occasionally be times, depending on local supply and demand, when there will be little current green energy surplus to trade across the supergrid- and certainly, there can be low wind inputs at times: http://tinypic.com/view.php?pic=dgnse0&s=8

That’s where large storage options like hydro reservoir pumped storage and compressed air cavern storage can help (for a few days), pumped up previously using surplus green power. They can supply power locally or via the supergrid to where it is needed. Power can also be generated from stored hydrogen or syngas, these stores being topped up ready for this using gas produced in P2G mode using surplus electricity from renewables previously and run into gas turbines when power is needed.   It’s easier to store gas than electricity (and it can be stored for long times) and even better/more efficient to store heat- so flexible CHP /DH plants with heat stores can also help: their power to heat output ratio can be increased to meet power shortfalls and any heat still needed supplied from the heat store, assuming it has been charged earlier when power demand was low. For the moment, most CHP plants run on fossil gas, but gradually they can be converted to run on biogas and low carbon synfuels/P2G, and solar and geothermal heat can also be used to feed the heat stores. And heat stores can store heat for long periods if necessary, even months. 

This flexible combination of power, heat and gas storage, linked up by supergrids and balanced as far as possible by demand management, expands the smart grid concept, so that, (along maybe with inputs from non-weather dependent renewable sources (hydro, tidal, geothermal, biomass) it should be able to deal with most if not all eventualities. Though that will depend on the economics: some say it will be expensive, others that it will avoid waste, improve balancing and cut costs. The current system is certainly wasteful, and adding variable renewables to it without system changes could be even more so- with surplus output at periods of low demand having to be curtailed. Smart electrical system flexibility can limit that and also some of the need for backup capacity.  Going further, to include heat and gas systems and stores in the mix, along with supergrid trading, should help even more, though as yet the optimal mix is unclear.   

For a review of advanced balancing options see:http://iopscience.iop.org/book/978-0-7503-1230-1 The Energy Matters post: http://euanmearns.com/how-smart-is-a-smart-grid/

Green gas- the fossil gas to hydrogen option

 Electrification with renewables isn’t the only energy decarbonisation option- gas can also be greened and there are a range of options for how to do this, with conversion to hydrogen currently being talked up: www.ukerc.ac.uk/network/network-news/guest-blog-decarbonising-heat-by-replacing-natural-gas-with-hydrogen.html

The H21 plan for Leeds looks to a switch to hydrogen gas for use in the gas network, rather than fossil gas. All domestic gas boilers and cookers would be converted to run on clean-burning hydrogen under the proposal to make Leeds a ‘hydrogen city’. At a cost estimated by Northern Gas Networks of  £2 bn, Leeds would be converted by 2025-30  and this could then be replicated in other major UK cities.  Steam-fed fossil-gas methane ‘reformer’ (SMR) plants around the city would convert methane from the national gas grid into hydrogen with the resultant carbon dioxide captured and piped to offshore undersea geological storage wells:

www.northerngasnetworks.co.uk/wp-content/uploads/2016/07/H21-Executive-Summary-Interactive-PDF-July-2016-V2.pdf

www.northerngasnetworks.co.uk/wp-content/uploads/2016/07/H21-Report-Interactive-PDF-July-2016.pdf

It’s a bold plan.  Gas conversion SMR technology is well established but CCS is untested on any scale, and cannot deliver 100% carbon sequestration. Moreover, though hydrogen burns without creating CO2, domestic appliances would have to be modified to burn it rather than methane, as they were in the 1970s, when the UK switched from hydrogen-rich ‘town gas’ to methane-rich North Sea natural gas. But that would be less disruptive than installing electric heat pumps in houses for heating and upgrading local power distribution grids to cope with the large extra demand- houses already have gas grid links with modern plastic pipes able to handle hydrogen.

Steam reformation is straight forward and the main current way of making hydrogen: CH4+ H2O > 3H2+ CO2.  However, some say why not use biogas produced from anaerobic digestion of domestic food and farm waste for at least some of the feedstock? Then the CO2 produced will be more or less balanced by biomass is growth- so no CCS is needed: www.sciencedirect.com/science/article/pii/S0961953414003663  Or how about synthetic green gas made by electrolysis using surplus electricity from wind farms- the so called Power to Gas (P2G) idea being developed in Germany? That’s based on the the Sabatier reaction: CO2 + 4H2 > CH4 + 2H2O. That will actually be looked at in the H21 programme, but, for now, the H21 team sees P2G as marginal: ‘Renewable based electrolysis could be used, but for the foreseeable future the required quantities do not look realistic’.

So for the moment it will be based on using fossil gas. The H21 team says ‘natural gas (predominantly methane), the lowest carbon dioxide emitter per unit of energy of any fossil fuel, produces about 180 gm/kWh CO2 equivalent whereas hydrogen emits zero (at the point of use). The change over from natural gas to hydrogen has the potential to provide a very deep carbon emission reduction. The true carbon footprint of hydrogen depends on its source. For example, grid power electrolysis has very high emissions whereas hydrogen made from stripping the carbon atom from natural gas has about 50 gm/kWh CO2 equivalent including indirect emissions, a large reduction over the existing unabated natural gas fuel’.

Labour has been pushing green gas generally and a parliamentary group has produced a new report, the Green Gas Book, with a series of essays by MPs and experts exploring the various biomethane, hydrogen, bioSNG and biopropane options.  It includes a chapter on the H21 plan and many mentions of it. The MPs see it, and green gas generally, as better than ripping out existing gas boilers! https://alansenergyblog.files.wordpress.com/2016/07/final-the-green-gas-book_96pp_v5.pdf

There are nevertheless some reservations about replacing natural gas with hydrogen.  Safety issues are often raised, and certainly hydrogen gas, like all flammable gases, needs careful handling.  But being lighter than air hydrogen tends vent out if there are leaks rather than filling up buildings.  And, as already noted, the coal-derived Town Gas used before the UK converted to North Sea gas had a high hydrogen content. However, the chapter in Labour’s booklet by Dr. Keith MacLean from the Energy Research Partnership, notes that ‘Current regulations only allow for 0.1% by volume of hydrogen to be blended into gas supplies. Since the level is much higher in other countries, like Germany where it is over 10%, there appears to be no insurmountable technical or safety reasons for this low limit. Upper ends of estimates of what could be added before adjustments would be required to appliances are about 20% by volume. However, although hydrogen has a high energy density by weight, it has a very low density by volume – about one third of natural gas. Therefore, even 20% by volume would only be equivalent to 6% by energy’.

So he says that ‘considering the supply side and network developments needed to enable hydrogen use in any quantity, it may make better technical and economic sense to convert to 100% hydrogen in a limited number of locations, rather than to convert many more areas for a blended solution, especially if this remains limited to such low levels’.  

A similar view emerged in a UKERC blog: the hydrogen option was an outlier, with the H21 approach only at best reducing CO2 by 59%: http://www.ukerc.ac.uk/network/network-news/guest-blog-heat-decarbonisation-calls-for-proven-technology.html

Maybe, but the Leeds H21 team see it as hopefully being replicable in cities elsewhere. Perhaps by then other feedstocks than fossil methane could be used e.g. biogas or P2G syn gas. That would avoid the need for CCS. But it would still be a complex multi-stage process with significant conversion losses, requiring more gas input to get the same heat output as would be available if the green gas was used directly for heating.  Certainly direct use of AD-derived biogas might be an easier option in some locations, and even though the volumes available are limited at present, they could be expanded. Ecotricity, Good Energy and Green Energy are already offering green biogas options to consumers via admixtures in the gas supply, and this route could expand as new biogas plans are developed- Ecotricity is planning to use grass as a feedstock in new gas mills!  

P2G and other syngas routes could also open up. In his chapter in the Green Gas Book Tony Glover, from the Energy Networks Association, notes that ‘National Grid’s 2015 Future Energy Scenarios report highlights the potential for a 10-fold increase in the number of green gas connections to the grid over the next decade, indicating a possible 416 connections by 2025 and 700 connections by 2035. This equates to approximately 40 TWh/year of green gas from AD injected to the grid by 2035, around 5% of the total UK gas demand and around 10% of the UK domestic gas demand. More recent industry estimates, which also include other renewable gases such as Bio-substitute natural gas (Bio SNG) and Power to Gas (P2G), suggest that the full potential of renewable gas may be over twice this level. Additionally, as UK gas demand continues to decrease, this proportion could become much higher’.

For a detailed analysis of all the green gas options and a review of some pioneering examples, see ‘Renewable Gas’, Jo Abbess, Palgrave, so far the definitive text, although this new more technical one looks good too: www.wiley-vch.de/publish/en/books/forthcomingTitles/CG00/1-118-54181-2/?sID=qq5uj8c4nsi1ombe73jpijkli0.

Next gen nuclear: will it happen?

Nuclear power may be having problems with its current range of Generation III reactor types, most of which are upgrades of standard water-cooled and moderated uranium reactors. There have been long deployment delays and crippling cost escalations for some of them- the EPR especially.  But, as ever, is is claimed that new nuclear technologies, the so-called Generation IV, will come to the rescue. They include revamped fast-neutron plutonium breeder reactors and molten salt reactors using thorium, along with helium- gas cooled high temperature reactors, all being developed on both the large and small scale. 

However, none yet actually exist and it will take time to develop commercial scale plants, or even prototypes. For example, in an interesting exchange of views in a debate on Thorium run by The Engineer, Fiona Rayment, director of fuel cycle solutions at the UK’s National Nuclear Laboratory, said ‘To develop radical new reactor designs, specifically designed around thorium, would take at least 30 years’:  https://www.theengineer.co.uk/issues/december-digital-edition-2/your-questions-answered-thorium-powered-nuclear/

She may be proved wrong, or other options may step in, but it is early days as yet, with, on the one hand, plenty of room for all types and scales, while on the other, it being unclear whether any of these ideas will prosper beyond prototypes. To some extent, the Generation IV technologies seem to be at the same stage as many renewables were twenty years or so ago, seeking to step beyond some historical precedents. Renewables of various types have managed that. It remains to be seen if Generation IV can. 

Some estimates of hoped for progress were produced in 2014 by the Generation IV International Forum (GIF), as below. On the basis of the industries past performance, they may be optimistic. GIF noted that the Fukushima disaster had led to some slow downs.

GIF Generation IV progress estimates

The Generation IV International Forum ‘Technology Roadmap Update for Generation IV Nuclear Energy Systems’ measures progress according to three (pre-commercialisation) phases:

*The viability phase, when basic concepts are tested under relevant conditions and all potential technical show-stoppers are identified and resolved;

*The performance phase, when engineering-scale processes, phenomena and materials capabilities are verified and optimised under prototypical conditions; and

*The demonstration phase, when detailed design is completed and licensing, construction and operation of the system are carried out, with the aim of bringing it to commercial deployment stage.

Its 2014 projections were as below, with demonstration phases presumably to follow on after:

·       Gas-cooled fast reactor: end of viability phase 2022; end of performance phase 2030.

·       Molten salt reactor: end of viability phase 2025; end of performance phase 2030.

·       Sodium-cooled fast reactor: end of viability phase 2012; end of performance phase 2022.

·       Supercritical-water-cooled reactor: end of viability phase 2015; end of performance phase 2025.

·       Very-high-temperature reactor: end of viability phase 2010; end of performance phase 2025.

·       Lead-cooled fast reactor: end of viability phase 2013; end of performance phase 2021.

Certainly, even on these estimates, there is still a long way to go before commercialization. GIF’s 2014 update to its 2002 Technology Roadmap review noted that ‘the development of technologies and associated system designs to the point of commercialisation for each of the six systems, as identified in the original Technology Roadmap, would have required considerable investment and international commitment. Since the “starting point” and R&D funding of the different Generation IV systems were not equivalent, the degree of technical progress over the past decade has not been uniform for all systems. A number of participating countries devoted significant resources to the development of the SFR and VHTR, for example, in large part due to the considerable historical effort associated with these technologies. More limited resources were dedicated to the other systems’: http://www.gen-4.org/gif/jcms/c_60729/technology-roadmap-update-2013

A more recent review, from a US perspective, the ‘Advanced Demonstration and Test Reactor Options Study’ carried out by the Argonne, Idaho and Oak Ridge National Labs, looked at basically the same six Gen-IV advanced reactor technology concepts. It concluded, a little more optimistically, that ‘the modular High Temperature Gas-Cooled Reactor (HTGR) and sodium-cooled fast reactor (SFR) have high enough technology readiness levels to support a commercial demonstration in the near future’. It went on ‘These technologies are considered mature as a result of several successful demonstrations brought about through billions of dollars of public and private investment in the U.S. over more than fifty years. These systems are also being built internationally, further confirming the high level of maturity of these systems as evaluated in this study’.

By contrast it said that ‘the fluoride-cooled high-temperature reactor (FHR) and lead-cooled fast reactor (LFR) are less mature and require additional research and development (R&D) and engineering demonstration in the near future. International and U.S. technology development activities are underway to mature these technologies, and technology demonstrations are planned. Other options examined (e.g., gas-cooled fast reactor) were even lower in maturity or did not have significant U.S. commercial interest (e.g., super-critical water-cooled reactor)’.

On this basis it suggested that HTGRs and SFRs ‘are mature enough to enable deployment of their first modules at commercial scale (the commercial demonstration step) in the early 2030s with additional commercial offerings soon thereafter,’ while the less-mature technologies, FHR and LFR, ‘are facing a longer technology development path to commercial offerings because they need a combination of both the engineering demonstration step and the performance demonstration step through 2040, prior to commercial offerings in ~2050’: https://art.inl.gov/INL ART TDO Documents/Advanced Demonstration and Test  Reactor Options Study/ADTR_Options_Study_Rev3.pdf

It will be interesting to see if any of these quite long term predictions prove to be correct.

As we have seen, not everyone is optimistic about the potential for significant gains, with a range of doubt being expressed. In a recent an interview-based review of advanced nuclear prospects in North America, Eaves looks at both sides of the debate, reporting on the enthusiasm expressed by some practitioners, but she also quotes former US Nuclear Regulatory Commission Chairman Allison Macfarlane as saying ‘I do not see past experience pointing at a positive direction’ : http://www.tandfonline.com/doi/full/10.1080/00963402.2016.1265353

Macfarlane was talking about High Temperature Reactors, but as we have seen, that comment might also be applicable, in the view of many critics, to most of the new nuclear options. Certainly, there are multiple challenges. Breakthroughs are always possible, and as one the the nuclear enthusiast that Eaves interviewed said ‘if we believe that nothing new can happen and everything is really hard, then it will be. That’s not to minimize the challenge, but it’s to say, if you start out thinking something is impossible, it’s very unlikely to happen.’

However, given the past history of nuclear power, and the multiple challenges, a degree of caution seems wise.

The above is extracted from a new book for the IoP ‘Nuclear Power: past, present and future’, which looks at the early days of nuclear power and how some of the ideas that emerged then are being re-explored as Generation IV: http://www.morganclaypoolpublishers.com/catalog_Orig/product_info.php?products_id=1062

As for beyond that, Generation V, if you have hopes for fusion, see this: http://thebulletin.org/fusion-reactors-not-what-they’re-cracked-be10699